Systems and Methods For Pressure-Cycled Stimulation During Gravity Drainage Operations

ABSTRACT

Systems and methods for pressure-cycled stimulation during gravity drainage operations. These systems and methods include increasing a pressure within a stimulation well that extends within a subterranean formation and subsequently decreasing the pressure within the stimulation well to increase production of viscous hydrocarbons from a production well. The systems and methods include repeating the increasing and the decreasing for a plurality of stimulation cycles and producing viscous hydrocarbons from the subterranean formation during the increasing, the decreasing, and the repeating. The increasing may include increasing a reservoir pressure within the subterranean formation to a pressure that is greater than a bubble point pressure of the viscous hydrocarbons, and the decreasing may include decreasing the reservoir pressure to a pressure that is less than the bubble point pressure of the viscous hydrocarbons.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority from Canadian Patent Application No. 2,800,443 filed Dec. 21, 2012 entitled SYSTEMS AND METHODS FOR PRESSURE-CYCLED STIMULATION DURING GRAVITY DRAINAGE OPERATIONS, the entirety of which are incorporated by reference herein.

FIELD OF THE DISCLOSURE

The present disclosure is directed generally to systems and methods for stimulating a subterranean formation during gravity drainage operations, and more specifically to systems and methods that include pressure-cycling a stimulation well during gravity drainage operations.

BACKGROUND OF THE DISCLOSURE

Certain subterranean formations may contain viscous hydrocarbons with a viscosity that is too high to naturally flow and/or to be produced from the subterranean formation using traditional primary and/or secondary hydrocarbon recovery techniques (i.e., natural and/or artificial pressure drive, respectively) due to the high viscosity thereof. As illustrative, non-exclusive examples, oil sands formations, tar sands formations, and/or bituminous sands formations may include high-viscosity bitumen, tar, and/or oil that will not flow under native reservoir conditions (or will not flow at a rate that is sufficient to provide for economic production of the viscous hydrocarbons).

Under these conditions, one or more traditional stimulation processes may be utilized to decrease the viscosity of the high-viscosity hydrocarbons, thereby permitting flow thereof and/or permitting flow at a rate that is sufficient for economic production of the viscous hydrocarbons. As an illustrative, non-exclusive example, gravity drainage operations, such as steam-assisted gravity drainage (SAGD), solvent-assisted steam-assisted gravity drainage (SA-SAGD), and/or vapor extraction (VAPEX) may be utilized to decrease the viscosity of the viscous hydrocarbons.

While these traditional stimulation processes may permit production of a portion of the viscous hydrocarbons from the subterranean formation, a rate at which the viscous hydrocarbons may be produced from the subterranean formation may be relatively low. Thus, there exists a need for improved systems and methods for stimulating and producing viscous hydrocarbons from a subterranean formation that includes the viscous hydrocarbons.

SUMMARY OF THE DISCLOSURE

Systems and methods for pressure-cycled stimulation during gravity drainage operations. The systems and methods include increasing a pressure within a stimulation well that extends within a subterranean formation and subsequently decreasing the pressure within the stimulation well to increase the production of viscous hydrocarbons from a production well. The systems and methods further include repeating the increasing and the decreasing for a plurality of stimulation cycles and producing viscous hydrocarbons from the subterranean formation via the production well during the increasing, the decreasing, and the repeating. The increasing may include increasing a reservoir pressure within the subterranean formation to a pressure that is greater than a bubble point pressure of the viscous hydrocarbons and/or an initial reservoir pressure, and the decreasing may include decreasing the reservoir pressure to a pressure that is less than the bubble point pressure of the viscous hydrocarbons.

In some embodiments, the increasing may include providing a stimulant fluid stream to the stimulation well. In some embodiments, the systems and methods further may include maintaining the reservoir pressure above an upper pressure threshold that is greater than the bubble point pressure and/or the initial reservoir pressure for at least a threshold pressurized time. In some embodiments, the maintaining may include controlling a flow rate of the stimulant fluid stream to the stimulation well.

In some embodiments, the decreasing may include ceasing the provision of the stimulant fluid stream to the stimulation well and/or decreasing the flow rate of the stimulant fluid stream to the stimulation well. In some embodiments, the decreasing may include maintaining the reservoir pressure below a lower pressure threshold that is less than the bubble point pressure for at least a threshold depressurized time.

In some embodiments, the systems and methods further may include monitoring the reservoir pressure. In some embodiments, the systems and methods may include initiating the increasing and/or the decreasing based, at least in part, on the monitoring.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of illustrative, non-exclusive examples of a viscous hydrocarbon production system that may be utilized with and/or include the systems and methods according to the present disclosure.

FIG. 2 is a plot of reservoir pressure vs. time that may be experienced within a subterranean formation that is utilized with and/or included in the systems and methods according to the present disclosure.

FIG. 3 is a flowchart depicting methods according to the present disclosure of stimulating and producing viscous hydrocarbons from a subterranean formation that includes the viscous hydrocarbons.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

FIG. 1 is a schematic representation of illustrative, non-exclusive examples of a viscous hydrocarbon production system 10 that may be utilized with and/or include the systems and methods according to the present disclosure. Viscous hydrocarbon production system 10 also may be referred to herein as hydrocarbon production system 10. The viscous hydrocarbon production system includes a stimulation well 40 and a production well 20 that both extend within a subterranean formation 16 that is present within a subsurface region 14.

Subterranean formation 16 may be any suitable structure that contains viscous hydrocarbons 18 therein. As illustrative, non-exclusive examples, the subterranean formation may be an oil sands formation, a tar sands formation, and/or a bituminous sands formation. Illustrative, non-exclusive examples of viscous hydrocarbons 18 include bitumen, tar, an unconventional hydrocarbon reserve, and/or a hydrocarbon reserve with a viscosity that is too high to be produced from the subterranean formation using primary and/or secondary hydrocarbon recovery operations.

Another illustrative, non-exclusive example of viscous hydrocarbons 18 according to the present disclosure include viscous hydrocarbons that contain solution gas adsorbed therein. This may include solution gas that is adsorbed within the viscous hydrocarbons and has a bubble point pressure of greater than 100 kilopascals (kPa), greater than 200 kPa, greater than 300 kPa, greater than 400 kPa, greater than 500 kPa, greater than 750 kPa, greater than 1000 kPa, greater than 1250 kPa, greater than 1500 kPa, greater than 2000 kPa, greater than 2500 kPa, or greater than 3000 kPa. Additionally or alternatively, this also may include solution gas that is adsorbed within the viscous hydrocarbons and has a bubble point pressure of less than 5000 kPa, less than 4500 kPa, less than 4000 kPa, less than 3500 kPa, less than 3000 kPa, less than 2500 kPa, less than 2000 kPa, less than 1500 kPa, or less than 1000 kPa.

It is within the scope of the present disclosure that, as discussed, subterranean formation 16 and/or viscous hydrocarbons 18 also may include, contain, and/or be mixed with one or more non-condensable gasses. Illustrative, non-exclusive examples of non-condensable gasses include methane, nitrogen gas and carbon dioxide.

As schematically illustrated in FIG. 1, production well 20 and stimulation well 40 may be defined by respective, spaced-apart, wellbores 22 and 42 that may extend from surface region 12, through subsurface region 14, and/or within subterranean formation 16. It is within the scope of the present disclosure that wellbores 22 and 42 may include and/or define any suitable individual and/or relative orientation. As illustrative, non-exclusive examples, wellbores 22 and 42 and/or portions thereof may include and/or be vertical wellbores, horizontal wellbores, and/or deviated wellbores. As another illustrative, non-exclusive example, and as shown in FIG. 1, a horizontal portion 43 of stimulation well 40 (or wellbore 42 thereof) may extend within subterranean formation 16 and vertically above a horizontal portion 23 of production well 20 (or wellbore 22 thereof).

Additionally or alternatively, at least a parallel portion of stimulation well 40 may be parallel to, or at least substantially parallel to, a respective parallel portion of production well 20 (such as horizontal portions 43 and 23, respectively, in FIG. 1). As discussed in more detail herein, this relative orientation of production well 20 with respect to stimulation well 40 may permit reduced viscosity hydrocarbon stream 26 to flow into production well 20 under the influence of gravity. Illustrative, non-exclusive examples of the parallel portion of production well 20 and/or the parallel portion of stimulation well 40 include portions that comprise at least 25%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, or at least 90% of a length of the production well and/or the stimulation well.

Stimulation well 40 may be associated with, proximal to, at least partially coextensive with, and/or in fluid communication with a stimulation chamber 60. Stimulation chamber 60 may include any suitable portion of subterranean formation 16 and/or wellbore 42 of stimulation well 40 and also may be referred to herein as a steam chamber 60 and/or a vapor chamber 60. As illustrated in FIG. 1, at least a portion of stimulation chamber 60 may be coextensive with, or at least partially coextensive with, at least a portion of stimulation well 40 and/or wellbore 42 thereof. As an illustrative, non-exclusive example, stimulation chamber 60 may surround and/or be at least partially concentric with at least a portion of wellbore 42.

The viscous hydrocarbon production system also includes a stimulant fluid supply system 44, which is configured to provide a stimulant fluid stream 46 to subterranean formation 16 via the stimulation well. Stimulant fluid supply system 44 may include any suitable structure that may be adapted, configured, and/or designed to supply stimulant fluid stream 46 to subterranean formation 16 via stimulation well 40. As illustrative, non-exclusive examples, stimulant fluid supply system 44 may include any suitable pump 47, valve 48, compressor 49, pipe and/or fluid conduit 50, and/or source 51 of stimulant fluid for stimulant fluid stream 46.

The stimulant fluid stream 46 that is provided to the subterranean formation by the stimulant fluid supply system via stimulation well 40 may physically, chemically, and/or thermally contact viscous hydrocarbons 18 that are within, associated with, and/or proximal to stimulation chamber 60 to decrease the viscosity of the viscous hydrocarbons, thereby generating a reduced viscosity hydrocarbon stream 26 therefrom. The reduced viscosity hydrocarbon stream may flow through subterranean formation 16 to production well 20, and the production well may convey the reduced viscosity hydrocarbon stream from the subterranean formation to and/or proximal to a surface region 12, thereby producing the reduced viscosity hydrocarbon stream from the subterranean formation.

Viscous hydrocarbon production system 10 optionally may further include a controller 80, which is programmed or otherwise configured to control the operation of at least a portion of the viscous hydrocarbon production system. Controller 80 may include any suitable structure that is adapted, configured, and/or programmed to control the operation of at least a portion of viscous hydrocarbon production assembly 10. As illustrative, non-exclusive examples, controller 80 may include and/or be a computer, a personal computer, and/or a dedicated control device, and controller 80 may control the operation of viscous hydrocarbon production assembly 10 in any suitable manner. This may include controlling the operation of the viscous hydrocarbon production assembly according to methods 200 that are discussed in more detail herein with reference to FIG. 3.

As an illustrative, non-exclusive example, stimulation well 40 and/or stimulant fluid supply system 44 may include one or more pumps 47 and/or valves 48, and controller 80 may control the operation of pumps 47 and/or valves 48 to control a flow rate of stimulant fluid stream 46 to the subterranean formation. As another illustrative, non-exclusive example, production well 20 may include one or more pumps 27 and/or valves 28, and controller 80 may control the operation of pumps 27 and/or valves 28 to control a flow rate of reduced viscosity hydrocarbon stream 26 therethrough. This may include increasing a rotational frequency, or output, of pumps 27 and/or pumps 47 to increase a flow rate of reduced viscosity hydrocarbon stream 26 and/or stimulant fluid stream 46, respectively, decreasing a rotational frequency of pumps 27 and/or pumps 47 to decrease the flow rate of stream 26 and/or stream 46, opening valves 28 and/or valves 48 to increase the flow rate of stream 26 and/or stream 46, and/or closing valves 28 and/or valves 48 to decrease the flow rate of stream 26 and/or stream 46.

As a further optional feature, and as indicated in dashed lines in FIG. 1, viscous hydrocarbon production system 10 may include one or more detectors 90 that may be configured to detect one or more properties, which also may be referred to herein as reservoir properties, of subterranean formation 16, stimulation well 40, stimulant fluid supply system 44, and/or production well 20. As illustrative, non-exclusive examples, detectors 90 may detect a pressure, a temperature, and/or a fluid flow rate within subterranean formation 16, stimulation well 40, stimulant fluid supply system 44, and/or production well 20. As more specific but still illustrative, non-exclusive examples, detectors 90 may detect a reservoir pressure within the subterranean formation, a bottom hole pressure within the stimulation well, a wellhead pressure of the production well, and/or a wellhead temperature of the production well. When viscous hydrocarbon production system 10 includes both controller 80 and one or more detectors 90, the controller may be configured to control and/or otherwise regulate at least a portion of the system, such as the pressure within the stimulation well and/or the flow of stream 26 and/or stream 46, responsive to properties detected by the one or more detectors.

It is within the scope of the present disclosure that stimulant fluid stream 46 may reduce the viscosity of viscous hydrocarbons 18 that are present within subterranean formation 16 to generate reduced viscosity hydrocarbon stream 26 in any suitable manner. As an illustrative, non-exclusive example, stimulant fluid stream 46 may include and/or be a diluent and/or a solvent for viscous hydrocarbons 18, and the viscous hydrocarbons may mix with, absorb, and/or be diluted by stimulant fluid stream 46, thereby generating reduced viscosity hydrocarbon stream 26. Additionally or alternatively, and as another illustrative, non-exclusive example, stimulant fluid stream 46 may have an elevated temperature and may transfer thermal energy to viscous hydrocarbons 18, thereby increasing a temperature of the viscous hydrocarbons, decreasing the viscosity thereof, and generating the reduced viscosity hydrocarbon stream. Illustrative, non-exclusive examples of stimulant fluid stream 46 include fluid streams that include and/or contain water, steam, a solvent for the viscous hydrocarbons, and/or a diluent for the viscous hydrocarbons, and these fluid streams may be supplied to the subterranean formation at an elevated temperature (i.e., a temperature that is greater than a temperature of the subterranean formation).

As discussed, reduced viscosity hydrocarbon stream 26 may include viscous hydrocarbons 18 that were present within subterranean formation 16 prior to formation of viscous hydrocarbon production assembly 10. However, and as also discussed, a viscosity of reduced viscosity hydrocarbon stream 26 may be less than a viscosity of viscous hydrocarbons 18 due to one or more interactions between viscous hydrocarbons 18 and stimulant fluid stream 46. As an illustrative, non-exclusive example, the reduced viscosity hydrocarbon stream may include at least a portion of the stimulant fluid stream, with the portion of the stimulant fluid stream reducing the viscosity of the viscous hydrocarbons that are present within the reduced viscosity hydrocarbon stream. As another illustrative, non-exclusive example, a temperature of the reduced viscosity hydrocarbon stream may be greater than an ambient temperature within the subterranean formation and/or a temperature of the viscous hydrocarbons prior to stimulant fluid stream 46 being supplied to the subterranean formation.

The systems and methods disclosed herein may be utilized to increase, relative to more traditional stimulation and/or production strategies, a rate of production of viscous hydrocarbons 18 from subterranean formation 16. As an illustrative, non-exclusive example, traditional gravity drainage processes, such as stream-assisted gravity drainage (SAGD), solvent-assisted steam-assisted gravity drainage (SA-SAGD), and/or vapor extraction (VAPEX) may utilize a stimulation well and a production well that may define a relative orientation that is similar to the relative orientation of stimulation well 40 and production well 20 of FIG. 1. However, the operation and/or control of the stimulation well and the production well during the traditional gravity drainage processes are distinctly different from the operation and/or control of viscous hydrocarbon production system 10 of FIG. 1.

In a traditional gravity drainage process, a stimulant fluid stream may be provided continuously, or at least substantially continuously, to a subterranean formation via a stimulation well. The stimulant fluid stream may contact viscous hydrocarbons that are present within the subterranean formation, thereby decreasing a viscosity thereof, to produce a reduced viscosity hydrocarbon stream that may flow through the subterranean formation to a production well. The production well may convey the reduced viscosity hydrocarbon stream from the subterranean formation to a surface region.

While such a traditional gravity drainage process may produce viscous hydrocarbons from the subterranean formation, it suffers from several limitations. As an illustrative, non-exclusive example, a non-condensable gas may evolve from viscous hydrocarbons and/or may otherwise be present within the subterranean formation, and this non-condensable gas may separate and/or insulate the viscous hydrocarbons that are present within the subterranean formation from the stimulant fluid stream, thereby decreasing an effectiveness of the stimulant fluid stream at decreasing the viscosity of the viscous hydrocarbons.

In contrast to these traditional gravity drainage processes, the systems and methods disclosed herein include periodically cycling a reservoir pressure within subterranean formation 16. This is discussed in more detail herein with reference to FIGS. 2-3 and may include cycling the reservoir pressure between an upper pressure threshold that is greater than a bubble point pressure of viscous hydrocarbons 18 and a lower pressure threshold that is less than the bubble point pressure of the viscous hydrocarbons.

As used herein, the phrase “reservoir pressure” may refer to a pressure that exists within the subterranean formation and/or a pressure of the viscous hydrocarbons that are present within the subterranean formation. The reservoir pressure also may be referred to herein as the pressure within subterranean formation 16 and/or the pressure of the subterranean formation 16. This reservoir pressure may be different from a “bottom hole pressure” that may be measured within a well (such as production well 20 and/or stimulation well 40) that extends within the subterranean formation. The well may be in direct, or at least substantially direct, fluid communication with surface region 12 via a wellbore (such as wellbore 22 and/or 42) thereof, thus permitting substantial fluctuations in the bottom hole pressure thereof, such as by providing a fluid to and/or removing a fluid from the wellbore. In contrast, viscous hydrocarbons 18, together with a matrix material 19 (such as rock, gravel, and/or sand) that may be present within subterranean formation 16, may resist fluid flow therethrough. Thus, the pressure within the subterranean formation may differ significantly from the bottom hole pressure.

With this in mind, the systems and methods disclosed herein may include increasing and/or decreasing the reservoir pressure to pressures that are above and/or below the bubble point pressure of the viscous hydrocarbons. When the reservoir pressure is lowered to a pressure that is less than the bubble point pressure of viscous hydrocarbons 18 (such as the lower pressure threshold), one or more gasses and/or volatile hydrocarbons that are included within viscous hydrocarbon 18 may evolve and/or be liberated from the viscous hydrocarbons. These gasses and/or volatile hydrocarbons may be referred to herein as solution gas. When this solution gas is evolved or otherwise released or discharged from the viscous hydrocarbons, it produces bubbles of the liberated solution gas in viscous hydrocarbons. These bubbles of liberated solution gas may cause the viscous hydrocarbons to swell and/or otherwise may increase a volume and/or decrease a density thereof. This swelling may provide a motive force for flow of the viscous hydrocarbons within subterranean formation 18 and may increase a flow rate of reduced viscosity hydrocarbon stream 26 into production well 20.

The liberated solution gas may provide an additional motive force for the production of reduced viscosity hydrocarbon stream 26 from production well 20. In addition, decreasing the reservoir pressure may permit non-condensable gas to mix with stimulant fluid stream 46, mix with reduced viscosity hydrocarbon stream 26, and/or be produced from the subterranean formation via production well 20. This may decrease a potential for the non-condensable gas to separate and/or otherwise insulate viscous hydrocarbons 14 from stimulant fluid stream 26.

The periodic cycling of the reservoir pressure according to the systems and methods disclosed herein may cause, contribute to, and/or otherwise generate a corresponding cyclic, staged, sequential, and/or stepped growth of stimulation chamber 60 (and/or a volume thereof). As an illustrative, non-exclusive example, and during a given (i.e., a particular or illustrative) pressure cycle, which also may be referred to herein as a stimulation cycle, the reservoir pressure may be increased to a value that is greater than the upper pressure threshold for a first period of time, before being decreased (and/or permitted to decrease) to a value that is less than the lower pressure threshold for a second period of time. The first period of time also may be referred to herein as a threshold pressurized time, and the second period of time, which also may be referred to herein as a threshold pressurized time, also may be referred to herein as a threshold depressurized time.

Referring again to FIG. 1, a volume, outer perimeter, or other outer boundary of stimulation chamber 60 is schematically indicated at 62 and represents the outer boundary of the stimulation chamber subsequent to the given pressure cycle. As additional pressure cycles are performed, the volume of the stimulation chamber may continue to increase, as indicated at 64 and 66, with each successive cycle. The pressure cycles may be repeated any suitable number of times and/or with any suitable frequency and may produce a corresponding growth in the volume of stimulation chamber 60 with each pressure cycle.

FIG. 2 is a plot 100 of reservoir pressure vs. time that may be experienced within a subterranean formation that is utilized with the systems and methods according to the present disclosure. In FIG. 2, the lower pressure threshold is indicated at 122, the upper pressure threshold is indicated at 124, and the bubble point pressure is indicated at 126, with each of these pressures being discussed in more detail herein with reference to FIG. 1.

In the illustrative, non-exclusive example of FIG. 2, the reservoir pressure is relatively constant, as indicated at 120, during a period of time 102 that is prior to the formation of stimulation and/or production wells within the subterranean formation and/or prior to stimulation of and/or production from the subterranean formation. This pressure 120 will generally be greater than bubble point pressure 126 due to chemical equilibration within the subterranean formation that may take place over thousands of years.

However, and subsequent to formation of at least one stimulation well and at least one production well within the subterranean formation to generate a viscous hydrocarbon production assembly that may be at least substantially similar to assembly 10 of FIG. 1, the reservoir pressure may be increased through supply of a stimulant fluid stream to the subterranean formation via the stimulation well. This increased pressure may be maintained for a pre-production time period 104, as illustrated in FIG. 2.

After the pre-production time period, the reservoir pressure may be cycled a plurality of times using the systems and methods according to the present disclosure in a plurality of pressure cycles 105, which also may be referred to herein as a plurality of stimulation cycles 105. In FIG. 2, stimulation cycles 105 occur during first cycle time 106, second cycle time 108, third cycle time 110, fourth cycle time 112, and fifth cycle time 114. In each of these stimulation cycles, and as discussed, the reservoir pressure is decreased to, near, and/or below, lower pressure threshold 122, which is less than bubble point pressure 126, before being increased to, near, and/or above upper pressure threshold 124, which is greater than bubble point pressure 126.

As discussed herein with reference to FIG. 1, a volume of a stimulation chamber that may be associated with the stimulation well may increase during each stimulation cycle 105, such as due to the removal of viscous hydrocarbons from the subterranean formation. As illustrated in FIG. 2, this increase in the volume of the stimulation chamber may produce a corresponding increase in the time that is needed for the reservoir pressure to transition between lower pressure threshold 122 and upper pressure threshold 124 (as shown by the increased width of the pressure drop that is associated with each stimulation cycle 105). This may be due to an increased volume of stimulant fluid that must be supplied to the stimulation chamber to increase the reservoir pressure from the lower pressure threshold to the upper pressure threshold, an increased volume of stimulant fluid that must flow from the stimulation chamber to decrease the reservoir pressure from the upper pressure threshold to the lower pressure threshold, and/or an increase in solution gas liberation due to a greater contact area between the stimulation chamber and the viscous hydrocarbons.

As discussed in more detail herein, the systems and methods according to the present disclosure also may include maintaining the reservoir pressure at, near, and/or above upper pressure threshold 124 for at least a threshold pressurized time. This is illustrated in FIG. 2 at 128. As illustrated in FIG. 2, the threshold pressurized time may be increased with each successive stimulation cycle 105. However, it is within the scope of the present disclosure that the threshold pressurized time may be constant and/or the same for at least a portion of the plurality of stimulation cycles 105 and/or that the threshold pressurized time may decrease from a given stimulation cycle to a subsequent stimulation cycle.

In addition, and as indicated in dashed-dot lines in FIG. 2 at 130 and discussed in more detail herein, the systems and methods according to the present disclosure also may include maintaining the reservoir pressure at, near, and/or below lower pressure threshold 122 for at least a threshold depressurized time. Similar to the threshold pressurized time, it is within the scope of the present disclosure that the threshold depressurized time may be at least substantially constant for each of the plurality of stimulation cycles, may increase from a given stimulation cycle to a subsequent stimulation cycle, and/or may decrease from a given stimulation cycle to a subsequent stimulation cycle.

In FIG. 2, each stimulation cycle 105 is indicated as being maintained at the same, or at least substantially the same, upper pressure threshold 124 and/or as being decreased to and/or maintained at the same, or at least substantially the same, lower pressure threshold 122. However, it is within the scope of the present disclosure that the upper pressure threshold and/or the lower pressure threshold may vary from one stimulation cycle 105 to the next stimulation cycle 105 and/or across the plurality of stimulation cycles 105. Regardless, the upper pressure threshold will be greater than bubble point pressure 126 and the lower pressure threshold will be less than the bubble point pressure.

FIG. 3 is a flowchart depicting methods 200 according to the present disclosure of stimulating and producing viscous hydrocarbons from a subterranean formation that includes the viscous hydrocarbons. Methods 200 may include pre-producing viscous hydrocarbons from the subterranean formation at 205 and/or monitoring a reservoir pressure within the subterranean formation at 210. Methods 200 also include increasing a pressure within a stimulation well at 215 and may include maintaining the reservoir pressure above an upper pressure threshold at 225. Methods 200 further include decreasing the pressure within the stimulation well at 230 and may include maintaining the reservoir pressure below a lower pressure threshold at 240. Methods 200 also include repeating the increasing at 215 and the decreasing at 230 for a plurality of stimulation cycles at 245, may include decreasing the viscosity of the viscous hydrocarbons at 250, and include producing viscous hydrocarbons from the subterranean formation as a reduced viscosity hydrocarbon stream at 255.

Pre-producing viscous hydrocarbons from the subterranean formation at 205 may include the use of any suitable systems and/or methods to produce, or otherwise remove, a portion of the viscous hydrocarbons from the subterranean formation. As an illustrative, non-exclusive example, the pre-producing may include pre-producing the viscous hydrocarbons from a production well that extends within the subterranean formation. It is within the scope of the present disclosure that the pre-producing at 205 may include pre-producing the viscous hydrocarbons for any suitable pre-production time prior to the increasing at 215, the decreasing at 230, and/or the repeating at 245. As illustrative, non-exclusive examples, the pre-producing may include pre-producing for at least 50, at least 100, at least 150, at least 200, at least 250, at least 300, at least 350, at least 400, at least 500, at least 600, at least 700, at least 800, at least 900, or at least 1000 days. As additional illustrative, non-exclusive examples, the pre-producing may include pre-producing using any suitable gravity draining process, such as SAGD, SA-SAGD, and/or VAPEX.

Monitoring the reservoir pressure at 210 may include the use of any suitable systems and/or methods to monitor, detect, determine, and/or calculate the reservoir pressure within the subterranean formation and/or to estimate and/or calculate the reservoir pressure from any suitable reservoir property that is related thereto. As an illustrative, non-exclusive example, the monitoring at 210 may include detecting the reservoir pressure. This detecting may include detecting the reservoir pressure by utilizing a suitable detector, such as the previously discussed detector 90. As another illustrative, non-exclusive example, the monitoring at 210 may include monitoring a reservoir property, illustrative, non-exclusive examples of which include a bottom hole pressure of the stimulation well, a bottom hole pressure of the production well, a wellhead pressure of the production well, a bottom hole temperature of the production well, and/or a wellhead temperature of the production well.

It is within the scope of the present disclosure that the monitoring at 210 also may, additionally or alternatively, include calculating the reservoir pressure. This may include calculating the reservoir pressure in any suitable manner, such as based upon one or more of the reservoir properties that are discussed herein. As an illustrative, non-exclusive example the reservoir pressure may be correlated to the bottom hole pressure of the production well and/or the bottom hole pressure of the stimulation well. Subsequently, the reservoir pressure may be calculated based upon a measured bottom hole pressure.

Increasing the pressure within the stimulation well at 215 may include increasing the pressure within the stimulation well to increase a reservoir pressure within the subterranean formation. This may include increasing the reservoir pressure to a pressure that is above an upper pressure threshold that is greater than a bubble point pressure of the viscous hydrocarbons that are present within the subterranean formation. This increasing may be accomplished by increasing any suitable pressure within the stimulation well, such as the bottom hole pressure, in any suitable manner.

Illustrative, non-exclusive examples of upper pressure thresholds according to the present disclosure include upper pressure thresholds that are greater than the bubble point pressure of the viscous hydrocarbons and/or greater than a pressure that existed in the subterranean formation prior to performing methods 200 by at least 10 kilopascals (kPa), at least 25 kPa, at least 50 kPa, at least 75 kPa, at least 100 kPa, at least 200 kPa, at least 300 kPa, at least 400 kPa, at least 500 kPa, at least 600 kPa, at least 700 kPa, at least 800 kPa, at least 900 kPa, or at least 1000 kPa. Additionally or alternatively, the upper pressure threshold may be greater than the bubble point pressure of the viscous hydrocarbons and/or greater than the pressure that existed in the subterranean formation prior to performing methods 200 by less than 1500 kPa, less than 1400 kPa, less than 1300 kPa, less than 1200 kPa, less than 1100 kPa, less than 1000 kPa, less than 900 kPa, less than 800 kPa, less than 700 kPa, less than 600 kPa, less than 500 kPa, less than 400 kPa, less than 300 kPa, less than 200 kPa, or less than 100 kPa.

As an illustrative, non-exclusive example, the increasing at 215 may include providing a stimulant fluid stream at 220, illustrative, non-exclusive examples of which are discussed in more detail herein, to the stimulation well and/or to a stimulation chamber thereof. The providing at 220 may increase the pressure within the stimulation well, thereby increasing the reservoir pressure through fluid communication therewith.

It is within the scope of the present disclosure that providing the stimulant fluid stream at 220 may include providing a total volume of the stimulant fluid stream for each stimulation cycle of the plurality of stimulation cycles. It is also within the scope of the present disclosure that the total volume of the stimulant fluid stream for a given stimulation cycle of the plurality of stimulation cycles may be less than a total volume of the stimulant fluid stream for a subsequent stimulation cycle of the plurality of stimulation cycles and/or that the total volume of the stimulant fluid stream may increase monotonically with each stimulation cycle of the plurality of stimulation cycles.

In addition, it is also within the scope of the present disclosure that the providing at 220 further may include controlling a flow rate of the stimulant fluid stream that is provided to the stimulation well to control a rate of the increasing at 215 (i.e., to control a rate of the increase in the pressure within the stimulation well and/or to control a rate of the increase in the reservoir pressure). As an illustrative, non-exclusive example, the controlling may include increasing the flow rate of the stimulant fluid stream responsive to the rate of the increasing at 215 being less than a threshold lower increasing rate. Additionally or alternatively, the controlling also may include decreasing the flow rate of the stimulant fluid stream responsive to the rate of the increasing at 215 being greater than a threshold upper increasing rate.

Maintaining the reservoir pressure above the upper pressure threshold at 225 may include maintaining the reservoir pressure above the upper pressure threshold for at least a threshold pressurized time using any suitable system and/or method. Illustrative, non-exclusive examples of threshold pressurized times according to the present disclosure include threshold pressurized times of at least 1 day, at least 2 days, at least 3 days, at least 4 days, at least 5 days, at least 10 days, at least 15 days, at least 20 days, at least 25 days, at least 30 days, at least 40 days, at least 50 days, at least 75 days, at least 100 days, at least 150 days, at least 200 days, at least 300 days, at least 400 days, at least 500 days, at least 600 days, at least 700 days, or at least 800 days. Additionally or alternatively, the threshold pressurized time may be less than 1500 days, less than 1250 days, less than 1000 days, less than 900 days, less than 800 days, less than 700 days, less than 600 days, less than 500 days, less than 400 days, less than 300 days, less than 250 days, less than 200 days, less than 190 days, less than 180 days, less than 170 days, less than 160 days, less than 150 days, less than 140 days, less than 130 days, less than 120 days, less than 110 days, or less than 100 days.

As an illustrative, non-exclusive example, the increasing at 215 may include providing the stimulant fluid stream to the stimulation well at a first flow rate and the maintaining at 225 may include providing the stimulant fluid stream to the stimulation well at a second flow rate that is less than the first flow rate. This may permit the reservoir pressure to be maintained above the upper pressure threshold despite flow of the stimulant fluid within the subterranean formation, production of the stimulant fluid via the production well, and/or condensation of the stimulant fluid within the subterranean formation.

As another illustrative, non-exclusive example, the maintaining at 225 also may include controlling the flow rate of the stimulant fluid stream that is provided to the stimulation well to maintain the reservoir pressure above the upper pressure threshold. This may include increasing the flow rate of the stimulant fluid stream responsive to the reservoir pressure being less than a lower maintaining pressure and/or decreasing the flow rate of the stimulant fluid stream responsive to the reservoir pressure being greater than an upper maintaining pressure.

As yet another illustrative, non-exclusive example, and when the stimulant fluid stream has a temperature that is greater than a temperature within the subterranean formation, the method also may include preserving a fluid temperature difference during the maintaining at 225. The fluid temperature difference may be defined as a difference between a stimulant fluid stream temperature and a reduced viscosity hydrocarbon stream temperature below a threshold fluid temperature difference. An illustrative, non-exclusive example of the stimulant fluid stream temperature includes a saturation temperature of the stimulant fluid stream at an injection pressure of the stimulant fluid stream. An illustrative, non-exclusive example of the reduced viscosity hydrocarbon stream temperature includes a temperature of the reduced viscosity hydrocarbon stream that is produced from the production well.

Illustrative, non-exclusive examples of threshold fluid temperature differences according to the present disclosure include threshold fluid temperature differences of less than 200° C., less than 190° C., less than 180° C., less than 170° C., less than 160° C., less than 150° C., less than 140° C., less than 130° C., less than 120° C., less than 110° C., less than 100° C., less than 90° C., less than 80° C., less than 70° C., less than 60° C., less than 50° C., less than 40° C., less than 30° C., less than 20° C., or less than 10° C. As used herein, preserving a temperature difference or preserving a temperature to be below a reference temperature and/or within a reference temperature range additionally or alternatively may be referred to as buffering, supplementing, sustaining, augmenting, and/or otherwise maintaining the temperature difference to be at or within the reference temperature or temperature range.

Preserving the fluid temperature difference below a threshold fluid temperature difference may include selectively changing a flow rate of the reduced viscosity hydrocarbon stream responsive to the temperature difference, such as to permit and/or provide for retention of at least a threshold quantity of thermal energy within the subterranean formation. This may include selectively increasing the flow rate of the reduced viscosity hydrocarbon stream responsive to determining that the fluid temperature difference is greater than the threshold fluid temperature difference and/or selectively decreasing the flow rate of the reduced viscosity hydrocarbon stream responsive to determining that the fluid temperature difference is less than the threshold fluid temperature difference.

Additionally or alternatively, preserving the fluid temperature difference below a threshold fluid temperature difference also may include selectively changing the flow rate of the stimulant fluid stream responsive to the fluid temperature difference, such as to permit and/or provide for supply of at least a threshold quantity of thermal energy to the subterranean formation. As illustrative, non-exclusive examples, the selectively changing may include selectively increasing the flow rate of the stimulant fluid stream responsive to determining that the temperature difference is greater than the threshold temperature difference and/or selectively decreasing the flow rate of the stimulant fluid stream responsive to determining that the fluid temperature difference is less than the threshold fluid temperature difference.

Decreasing the pressure within the stimulation well at 230 may include decreasing the pressure within the stimulation well to decrease the reservoir pressure. This may include decreasing the reservoir pressure to a pressure that is below a lower pressure threshold that is less than the bubble point pressure of the viscous hydrocarbons and may include increasing any suitable pressure within the stimulation well, such as the bottom hole pressure, in any suitable manner.

Illustrative, non-exclusive examples of lower pressure thresholds according to the present disclosure include lower pressure thresholds that are less than the bubble point pressure of the viscous hydrocarbons and/or less than the pressure that existed in the subterranean formation prior to performing methods 200 by at least 10 kilopascals (kPa), at least 25 kPa, at least 50 kPa, at least 75 kPa, at least 100 kPa, at least 200 kPa, at least 300 kPa, at least 400 kPa, at least 500 kPa, at least 600 kPa, at least 700 kPa, at least 800 kPa, at least 900 kPa, or at least 1000 kPa. Additionally or alternatively, the lower pressure threshold also may be less than the bubble point pressure of the viscous hydrocarbons and/or less than the pressure that existed in the subterranean formation prior to performing methods 200 by less than 1500 kPa, less than 1400 kPa, less than 1300 kPa, less than 1200 kPa, less than 1100 kPa, less than 1000 kPa, less than 900 kPa, less than 800 kPa, less than 700 kPa, less than 600 kPa, less than 500 kPa, less than 400 kPa, less than 300 kPa, less than 200 kPa, or less than 100 kPa.

As an illustrative, non-exclusive example, the decreasing at 230 may include decreasing the flow rate of the stimulant fluid that is supplied to the stimulation well, as indicated in FIG. 3 at 235. The decreasing at 235 may include ceasing the supplying at 220 and/or decreasing a magnitude of the flow rate of the stimulant fluid stream.

As discussed in more detail herein, the viscous hydrocarbons that are present within the subterranean formation may evolve, or liberate, a solution gas when the pressure within the subterranean formation is decreased below the bubble point pressure of the viscous hydrocarbons. As also discussed in more detail herein, the liberated solution gas may generate gas bubbles within the viscous hydrocarbons, thereby increasing a volume of the viscous hydrocarbons. This may provide a motive force for flow of the viscous hydrocarbons within the subterranean formation and/or may convey at least a portion of the viscous hydrocarbons into the stimulation chamber that is associated with the stimulation well.

Maintaining the reservoir pressure below the lower pressure threshold at 240 may include maintaining the reservoir pressure below the lower pressure threshold for at least a threshold depressurized time using any suitable system and/or method. Illustrative, non-exclusive examples of threshold depressurized times according to the present disclosure include threshold depressurized times of at least 1, at least 2, at least 3, at least 4, at least 5, at least 10, at least 15, at least 20, at least 25, at least 30, at least 40, at least 50, at least 75, at least 100, at least 150, or at least 200 days. Additionally or alternatively, the threshold depressurized time may be less than 300, less than 250, less than 200, less than 190, less than 180, less than 170, less than 160, less than 150, less than 140, less than 130, less than 120, less than 110, or less than 100 days.

It is within the scope of the present disclosure that the threshold depressurized time may be constant, or at least substantially constant, for each stimulation cycle. Alternatively, it is also within the scope of the present disclosure that the threshold depressurized time may be different for at least one stimulation cycle relative to at least one other stimulation cycle. As an illustrative, non-exclusive example, the threshold depressurized time may increase with each stimulation cycle relative to a previous stimulation cycle.

The repeating at 245 may include repeating the increasing at 215 and the decreasing at 230 for the plurality of stimulation cycles. The repeating may include performing the increasing at 215 and subsequently performing the decreasing at 230 in each stimulation cycle of the plurality of stimulation cycles and may include repeating any suitable number of times and/or based on any suitable criteria. In addition, the repeating at 245 also may include performing any suitable traditional gravity drainage process, illustrative, non-exclusive examples of which are discussed in more detail herein, prior to the plurality of stimulation cycles, between at least a portion of the plurality of stimulation cycles, and/or between each of the plurality of stimulation cycles.

As an illustrative, non-exclusive example, the repeating may include repeating at least 2, at least 3, at least 4, at least 6, at least 8, at least 10, at least 15, at least 20, at least 25, or at least 30 times during a corresponding number of stimulation cycles. As another illustrative, non-exclusive example, the repeating may include repeating at least once every 25 days, every 30 days, every 40 days, every 50 days, every 60 days, every 70 days, every 80 days, every 90 days, every 100 days, every 110 days, every 120 days, every 130 days, every 140 days, every 150 days, every 200 days, every 250 days, every 300 days, or every 350 days.

It is within the scope of the present disclosure that the repeating at 245 may be based, at least in part, on any suitable criteria. As illustrative, non-exclusive examples, the repeating may include repeating the decreasing at 230 based, at least in part, on determining that the reservoir pressure is greater than the upper pressure threshold and/or has been greater than the upper pressure threshold for at least the threshold pressurized time. As another illustrative, non-exclusive example, the repeating at 245 also may include repeating the increasing at 215 based, at least in part, on determining that the reservoir pressure is less than the lower pressure threshold and/or that the reservoir pressure has been less than the lower pressure threshold for at least the threshold depressurized time.

Decreasing the viscosity of the viscous hydrocarbons at 250 may include decreasing the viscosity of at least a portion of the viscous hydrocarbons in any suitable manner, with the portion of the viscous hydrocarbons forming and/or contributing to the reduced viscosity hydrocarbon stream. It is within the scope of the present disclosure that the decreasing at 250 may be performed concurrently with and/or be a result of any suitable portion of methods 200.

As an illustrative, non-exclusive example, and when the stimulant fluid stream has a temperature that is greater than a temperature within the subterranean formation, the decreasing at 250 may include heating the viscous hydrocarbons to decrease the viscosity of the viscous hydrocarbons. As another illustrative, non-exclusive example, and when the stimulant fluid stream is a diluent and/or solvent for the viscous hydrocarbons, the decreasing at 250 may include diluting the viscous hydrocarbons with the stimulant fluid stream to decrease the viscosity of the viscous hydrocarbons.

Producing the viscous hydrocarbons from the subterranean formation at 255 may include producing the viscous hydrocarbons as a reduced viscosity hydrocarbon stream, from a production well that extends within the subterranean formation and is spaced apart from the stimulation well. It is within the scope of the present disclosure that the producing at 255 may include producing during, in parallel with, and/or concurrently with a remainder of methods 200, including at least the increasing at 215, the decreasing at 230, and the repeating at 245. This may include continuously producing the viscous hydrocarbons and/or producing the viscous hydrocarbons during at least 75%, at least 80%, at least 85%, at least 90%, at least 95%, at least 97.5%, at least 99%, or all of a time period during which the increasing at 215, the decreasing at 230, and/or the repeating at 245 are performed.

It is within the scope of the present disclosure that the producing at 255 may include maintaining a constant, or an at least substantially constant, rate of production of the reduced viscosity hydrocarbon stream during each stimulation cycle of methods 200 and/or during a majority, a substantial majority, or all of a time period during which methods 200 are performed.

However, it is also within the scope of the present disclosure that the producing at 255 may include varying the rate of production of the reduced viscosity hydrocarbon stream within a given stimulation cycle and/or from stimulation cycle to stimulation cycle. In addition, it is also within the scope of the present disclosure that the producing at 255 may include maintaining at least a threshold production rate of the reduced viscosity hydrocarbon stream during an entirety of the time period during which methods 200 are performed.

In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently. It is also within the scope of the present disclosure that the blocks, or steps, may be implemented as logic, which also may be described as implementing the blocks, or steps, as logics. In some applications, the blocks, or steps, may represent expressions and/or actions to be performed by functionally equivalent circuits or other logic devices. The illustrated blocks may, but are not required to, represent executable instructions that cause a computer, processor, and/or other logic device to respond, to perform an action, to change states, to generate an output or display, and/or to make decisions.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

In the event that any patents, patent applications, or other references are incorporated by reference herein and define a term in a manner or are otherwise inconsistent with either the non-incorporated portion of the present disclosure or with any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was originally present.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

Illustrative, non-exclusive examples of systems and methods according to the present disclosure are presented in the following enumerated paragraphs. It is within the scope of the present disclosure that an individual step of a method recited herein, including in the following enumerated paragraphs, may additionally or alternatively be referred to as a “step for” performing the recited action.

A1. A method of stimulating and producing viscous hydrocarbons from a subterranean formation that includes the viscous hydrocarbons, the method comprising:

increasing a pressure within a stimulation well that extends within the subterranean formation to increase a reservoir pressure to a pressure that is above an upper pressure threshold that is greater than a bubble point pressure of the viscous hydrocarbons;

decreasing the pressure within the stimulation well to decrease the reservoir pressure to a pressure that is below a lower pressure threshold that is less than the bubble point pressure of the viscous hydrocarbons;

repeating the increasing the pressure and the decreasing the pressure for a plurality of stimulation cycles; and

producing, as a reduced viscosity hydrocarbon stream, the viscous hydrocarbons from a production well that extends within the subterranean formation and is spaced apart from the stimulation well, wherein the producing includes producing during the increasing the pressure, the decreasing the pressure, and the repeating.

A2. The method of paragraph A1, wherein the increasing the pressure includes providing a stimulant fluid stream to the stimulation well, and optionally wherein the stimulant fluid stream includes at least one, optionally at least two, optionally at least three, or optionally at least four of water, steam, a solvent for the viscous hydrocarbon, and a diluent for the viscous hydrocarbon.

A3. The method of paragraph A2, wherein the providing a stimulant fluid stream includes providing the stimulant fluid stream to a stimulation chamber that is associated with the stimulation well, optionally wherein the stimulation chamber includes at least one of a steam chamber and a vapor chamber, optionally wherein the stimulation chamber is at least partially coextensive with at least a portion of a wellbore that defines the stimulation well, optionally wherein the stimulation chamber surrounds at least a portion of the wellbore, and further optionally wherein the stimulation chamber is at least partially concentric with at least a portion of the wellbore.

A4. The method of any of paragraphs A2-A3, wherein the providing a stimulant fluid stream includes providing a total volume of the stimulant fluid stream for each stimulation cycle of the plurality of stimulation cycles, wherein a total volume of the stimulant fluid stream for a given stimulation cycle of the plurality of stimulation cycles is less than a total volume of the stimulant fluid stream for a subsequent stimulation cycle of the plurality of stimulation cycles, and optionally wherein the total volume of the stimulant fluid stream increases monotonically with each stimulation cycle of the plurality of stimulation cycles.

A5. The method of any of paragraphs A2-A4, wherein the providing a stimulant fluid stream includes controlling a flow rate of the stimulant fluid stream to control a rate of the increasing, and optionally wherein the controlling a flow rate of the stimulant fluid stream to control a rate of the increasing includes at least one of:

-   -   (i) increasing the flow rate of the stimulant fluid stream         responsive to the rate of the increasing being less than a         threshold lower increasing rate; and     -   (ii) decreasing the flow rate of the stimulant fluid stream         responsive to the rate of the increasing being greater than a         threshold upper increasing rate.

A6. The method of any of paragraphs A1-A5, wherein, subsequent to the increasing the pressure and prior to the decreasing the pressure, the method further includes maintaining the reservoir pressure above the upper pressure threshold for at least a threshold pressurized time.

A7. The method of paragraph A6, wherein the increasing includes providing a/the stimulant fluid stream to the stimulation well at a first flow rate, and further wherein the maintaining the reservoir pressure above the upper pressure threshold includes providing the stimulant fluid stream to the stimulation well at a second flow rate that optionally is less than the first flow rate.

A8. The method of any of paragraphs A6-A7, wherein the maintaining includes controlling a/the flow rate of the stimulant fluid stream to maintain the reservoir pressure above the upper pressure threshold, and optionally wherein the controlling the flow rate of the stimulant fluid stream to maintain the reservoir pressure above the upper pressure threshold includes at least one of:

-   -   (i) increasing the flow rate of the stimulant fluid stream         responsive to the reservoir pressure being less than a lower         maintaining pressure; and     -   (ii) decreasing the flow rate of the stimulant fluid stream         responsive to the reservoir pressure being greater than an upper         maintaining pressure.

A9. The method of any of paragraphs A6-A8, wherein the threshold pressurized time is at least one of:

-   -   (i) at least 1, at least 2, at least 3, at least 4, at least 5,         at least 10, at least 15, at least 20, at least 25, at least 30,         at least 40, at least 50, at least 75, at least 100, at least         150, at least 200, at least 300, at least 400, at least 500, at         least 600, at least 700, or at least 800 days; and     -   (ii) less than 1500 days, less than 1250 days, less than 1000         days, less than 900 days, less than 800 days, less than 700         days, less than 600 days, less than 500 days, less than 400         days, less than 300, less than 250, less than 200, less than         190, less than 180, less than 170, less than 160, less than 150,         less than 140, less than 130, less than 120, less than 110, or         less than 100 days.

A10. The method of any of paragraphs A6-A9, wherein the method further includes preserving a fluid temperature difference between a/the stimulant fluid stream and the reduced viscosity hydrocarbon stream below a threshold fluid temperature difference during the maintaining.

A11. The method of paragraph A10, wherein the threshold fluid temperature difference is less than 200° C., less than 190° C., less than 180° C., less than 170° C., less than 160° C., less than 150° C., less than 140° C., less than 130° C., less than 120° C., less than 110° C., less than 100° C., less than 90° C., less than 80° C., less than 70° C., less than 60° C., less than 50° C., less than 40° C., less than 30° C., less than 20° C., or less than 10° C.

A12. The method of any of paragraphs A10-A11, wherein the preserving the fluid temperature difference includes at least one of:

-   -   (i) selectively changing a flow rate of the reduced viscosity         hydrocarbon stream responsive to the fluid temperature         difference;     -   (ii) selectively increasing the flow rate of the reduced         viscosity hydrocarbon stream responsive to determining that the         fluid temperature difference is greater than the threshold fluid         temperature difference; and     -   (iii) selectively decreasing the flow rate of the reduced         viscosity hydrocarbon stream responsive to determining that the         fluid temperature difference is less than the threshold fluid         temperature difference.     -   (iv) selectively changing a flow rate of the stimulant fluid         stream responsive to the fluid temperature difference;     -   (v) selectively increasing the flow rate of the stimulant fluid         stream responsive to determining that the fluid temperature         difference is greater than the threshold fluid temperature         difference;     -   (vi) selectively decreasing the flow rate of the stimulant fluid         stream responsive to determining that the fluid temperature         difference is less than the threshold fluid temperature         difference;

A13. The method of any of paragraphs A1-A12, wherein the decreasing the pressure includes at least one of ceasing providing a/the stimulant fluid stream to the stimulation well and decreasing a flow rate of the stimulant fluid stream to the stimulation well.

A14. The method of any of paragraphs A1-A13, wherein the decreasing the pressure includes liberating a solution gas from the viscous hydrocarbon while the viscous hydrocarbon is present within the subterranean formation.

A15. The method of any of paragraphs A13-A14, wherein the liberating includes generating a motive force for the producing.

A16. The method of any of paragraphs A14-A15, wherein the liberating includes increasing a volume of the viscous hydrocarbons.

A17. The method of any of paragraphs A14-A16, wherein the liberating includes conveying a portion of the viscous hydrocarbons into a/the stimulation chamber that is associated with the stimulation well.

A18. The method of any of paragraphs A1-A17, wherein the decreasing the pressure further includes producing a non-condensable gas from the subterranean formation.

A19. The method of any of paragraphs A1-A18, wherein, subsequent to the decreasing the pressure, the method further includes maintaining the reservoir pressure below the lower pressure threshold for at least a threshold depressurized time.

A20. The method of paragraph A19, wherein the threshold depressurized time is at least one of:

-   -   (i) at least 1, at least 2, at least 3, at least 4, at least 5,         at least 10, at least 15, at least 20, at least 25, at least 30,         at least 40, at least 50, at least 75, at least 100, at least         150, or at least 200 days; and     -   (ii) less than 300, less than 250, less than 200, less than 190,         less than 180, less than 170, less than 160, less than 150, less         than 140, less than 130, less than 120, less than 110, or less         than 100 days.

A21. The method of any of paragraphs A19-A20, wherein the threshold depressurized time at least one of:

-   -   (i) is constant for each stimulation cycle of the plurality of         stimulation cycles;     -   (ii) increases with each stimulation cycle of the plurality of         stimulation cycles; and     -   (iii) is different for at least one stimulation cycle of the         plurality of stimulation cycles relative to at least one other         stimulation cycle of the plurality of stimulation cycles.

A22. The method of any of paragraphs A1-A21, wherein the repeating includes repeating the increasing and the decreasing for at least 2, at least 3, at least 4, at least 6, at least 8, at least 10, at least 15, at least 20, at least 25, or at least 30 stimulation cycles.

A23. The method of any of paragraphs A1-A22, wherein the repeating includes repeating at least once every 25 days, every 30 days, every 40 days, every 50 days, every 60 days, every 70 days, every 80 days, every 90 days, every 100 days, every 110 days, every 120 days, every 130 days, every 140 days, every 150 days, every 200 days, every 250 days, every 300 days, or every 350 days.

A24. The method of any of paragraphs A1-A23, wherein the repeating includes performing the increasing the pressure and subsequently performing the decreasing the pressure in each stimulation cycle of the plurality of stimulation cycles.

A25. The method of any of paragraphs A1-A24, wherein the increasing the pressure includes providing a motive force for the producing.

A26. The method of any of paragraphs A1-A25, wherein the method further includes decreasing a viscosity of the viscous hydrocarbons prior to the producing.

A27. The method of any of paragraphs A1-A26, wherein the producing includes continuously producing the viscous hydrocarbons during at least 75%, at least 80%, at least 85%, at least 90%, at least 95%, at least 97.5%, at least 99%, or all of a time period during which the increasing the pressure, the decreasing the pressure, and the repeating occurs.

A28. The method of any of paragraphs A1-A27, wherein the producing further includes maintaining an at least substantially constant production rate during the producing.

A29. The method of any of paragraphs A1-A28, wherein the method further includes monitoring the reservoir pressure.

A30. The method of paragraph A29, wherein the decreasing the pressure includes decreasing the pressure based, at least in part, on determining that the reservoir pressure is greater than the upper pressure threshold.

A31. The method of paragraph A30, wherein the decreasing the pressure further includes decreasing the pressure based, at least in part, on determining that the reservoir pressure has been greater than the upper pressure threshold for at least a/the threshold pressurized time.

A32. The method of any of paragraphs A29-A31, wherein the increasing the pressure includes increasing the pressure based, at least in part, on determining that the reservoir pressure is less than the lower pressure threshold.

A33. The method of paragraph A32, wherein the increasing the pressure further includes increasing the pressure based, at least in part, on determining that the reservoir pressure has been less than the lower pressure threshold for at least a/the threshold depressurized time.

A34. The method of any of paragraphs A29-A33, wherein the monitoring the reservoir pressure includes monitoring a reservoir property, and optionally wherein the reservoir property includes at least one of the stimulation well bottom hole pressure, the production well bottom hole pressure, the production wellhead pressure, the production well bottom hole temperature, and the production wellhead temperature.

A35. The method of any of paragraphs A29-A34, wherein the monitoring the reservoir pressure includes calculating the reservoir pressure.

A36. The method of paragraph A35 when dependent from A34, wherein the calculating is based, at least in part, on the reservoir property.

A37. The method of any of paragraphs A1-A36, wherein the method further includes heating the viscous hydrocarbons to decrease a/the viscosity of a portion of the viscous hydrocarbons that forms the reduced viscosity hydrocarbon stream, optionally wherein the heating includes heating the viscous hydrocarbons with a/the stimulant fluid stream.

A38. The method of any of paragraphs A1-A37, wherein the method further includes diluting the viscous hydrocarbons to decrease a/the viscosity of a portion of the viscous hydrocarbons that forms the reduced viscosity hydrocarbon stream, optionally wherein the diluting includes diluting the viscous hydrocarbons with a/the stimulant fluid stream.

A39. The method of any of paragraphs A1-A38, wherein the producing further includes producing the viscous hydrocarbons from the production well for a pre-production time prior to at least the decreasing the pressure and the repeating, optionally using at least one of a steam-assisted gravity drainage process, a solvent-assisted steam-assisted gravity drainage process, and a vapor extraction process.

A40. The method of paragraph A39, wherein the pre-production time is at least 50, at least 100, at least 150, at least 200, at least 250, at least 300, at least 350, at least 400, at least 500, at least 600, at least 700, at least 800, at least 900, or at least 1000 days.

A41. The method of any of paragraphs A1-A40, wherein the method includes performing the method as part of at least one of a steam-assisted gravity drainage process, a solvent-assisted steam-assisted gravity drainage process, and a vapor extraction process.

A42. The method of any of paragraphs A1-A41, wherein the pressure within the stimulation well is a bottom hole pressure within the stimulation well.

A43. The method of any of paragraphs A1-A42, wherein the upper pressure threshold is at least one of:

-   -   (i) greater than the bubble point pressure of the viscous         hydrocarbons by at least 10 kilopascals (kPa), at least 25 kPa,         at least 50 kPa, at least 75 kPa, at least 100 kPa, at least 200         kPa, at least 300 kPa, at least 400 kPa, at least 500 kPa, at         least 600 kPa, at least 700 kPa, at least 800 kPa, at least 900         kPa, or at least 1000 kPa; and     -   (ii) greater than the bubble point pressure of the viscous         hydrocarbons by less than 1500 kPa, less than 1400 kPa, less         than 1300 kPa, less than 1200 kPa, less than 1100 kPa, less than         1000 kPa, less than 900 kPa, less than 800 kPa, less than 700         kPa, less than 600 kPa, less than 500 kPa, less than 400 kPa,         less than 300 kPa, less than 200 kPa, or less than 100 kPa.

A44. The method of any of paragraphs A1-A43, wherein the upper pressure threshold is at least one of:

-   -   (i) greater than a reservoir pressure prior to performing the         method by at least 10 kilopascals (kPa), at least 25 kPa, at         least 50 kPa, at least 75 kPa, at least 100 kPa, at least 200         kPa, at least 300 kPa, at least 400 kPa, at least 500 kPa, at         least 600 kPa, at least 700 kPa, at least 800 kPa, at least 900         kPa, or at least 1000 kPa; and     -   (ii) greater than the reservoir pressure prior to performing the         method by less than 1500 kPa, less than 1400 kPa, less than 1300         kPa, less than 1200 kPa, less than 1100 kPa, less than 1000 kPa,         less than 900 kPa, less than 800 kPa, less than 700 kPa, less         than 600 kPa, less than 500 kPa, less than 400 kPa, less than         300 kPa, less than 200 kPa, or less than 100 kPa.

A45. The method of any of paragraphs A1-A44, wherein the lower pressure threshold is at least one of:

-   -   (i) lower than the bubble point pressure of the viscous         hydrocarbons by at least 10 kilopascals (kPa), at least 25 kPa,         at least 50 kPa, at least 75 kPa, at least 100 kPa, at least 200         kPa, at least 300 kPa, at least 400 kPa, at least 500 kPa, at         least 600 kPa, at least 700 kPa, at least 800 kPa, at least 900         kPa, or at least 1000 kPa; and     -   (ii) lower than the bubble point pressure of the viscous         hydrocarbons by less than 1500 kPa, less than 1400 kPa, less         than 1300 kPa, less than 1200 kPa, less than 1100 kPa, less than         1000 kPa, less than 900 kPa, less than 800 kPa, less than 700         kPa, less than 600 kPa, less than 500 kPa, less than 400 kPa,         less than 300 kPa, less than 200 kPa, or less than 100 kPa.

A46. The method of any of paragraphs A1-A45, wherein the lower pressure threshold is at least one of:

-   -   (i) lower than a/the reservoir pressure prior to performing the         method by at least 10 kilopascals (kPa), at least 25 kPa, at         least 50 kPa, at least 75 kPa, at least 100 kPa, at least 200         kPa, at least 300 kPa, at least 400 kPa, at least 500 kPa, at         least 600 kPa, at least 700 kPa, at least 800 kPa, at least 900         kPa, or at least 1000 kPa; and     -   (ii) lower than the reservoir pressure prior to performing the         method by less than 1500 kPa, less than 1400 kPa, less than 1300         kPa, less than 1200 kPa, less than 1100 kPa, less than 1000 kPa,         less than 900 kPa, less than 800 kPa, less than 700 kPa, less         than 600 kPa, less than 500 kPa, less than 400 kPa, less than         300 kPa, less than 200 kPa, or less than 100 kPa.

A47. The method of any of paragraphs A1-A46, wherein the bubble point pressure of the viscous hydrocarbons is a pressure at which a/the solution gas begins to evolve from the viscous hydrocarbons that are present within the subterranean formation.

A48. The method of any of paragraphs A1-A47, wherein the bubble point pressure of the viscous hydrocarbons is at least one of:

-   -   (i) greater than 100 kilopascals (kPa), greater than 200 kPa,         greater than 300 kPa, greater than 400 kPa, greater than 500         kPa, greater than 750 kPa, greater than 1000 kPa, greater than         1250 kPa, greater than 1500 kPa, greater than 2000 kPa, greater         than 2500 kPa, or greater than 3000 kPa; and     -   (ii) less than 5000 kPa, less than 4500 kPa, less than 4000 kPa,         less than 3500 kPa, less than 3000 kPa, less than 2500 kPa, less         than 2000 kPa, less than 1500 kPa, or less than 1000 kPa.

A49. The method of any of paragraphs A1-A48, wherein at least a parallel portion of the stimulation well is at least substantially parallel to at least a parallel portion of the production well.

A50. The method of paragraph A49, wherein the parallel portion of the stimulation well includes at least 25%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, or at least 90% of a length of the stimulation well.

A51. The method of any of paragraphs A1-A50, wherein at least a horizontal portion of the stimulation well is at least substantially horizontal.

A52. The method of any of paragraphs A1-A51, wherein at least a horizontal portion of the production well is at least substantially horizontal.

A53. The method of any of paragraphs A1-A52, wherein the viscous hydrocarbons include at least one of bitumen, tar, an unconventional hydrocarbon reserve, and a hydrocarbon reserve with a viscosity that is too high to be produced from the subterranean formation using primary hydrocarbon recovery operations or secondary hydrocarbon recovery operations.

A54. The method of any of paragraphs A1-A53, wherein the subterranean formation includes at least one of an oil sands formation, a tar sands formation, and a bituminous sands formation.

B1. A system configured to produce viscous hydrocarbons from a subterranean formation, the system comprising:

a stimulation well that extends within the subterranean formation;

a stimulant fluid supply system that is configured to provide a stimulant fluid stream to the subterranean formation via the stimulation well;

a production well that is spaced-apart from the stimulation well, extends within the subterranean formation and is configured to produce a reduced viscosity hydrocarbon stream from the subterranean formation; and

a controller that is programmed to control the operation of the system using the method of any of paragraphs A1-A54.

B2. The system of paragraph B1, wherein the system includes the subterranean formation.

B3. The system of any of paragraphs B1-B2, wherein the system further includes a detector configured to detect a property of at least one of the subterranean formation, the stimulation well, and the production well.

B4. The system of paragraph B3, wherein the property includes at least one of a pressure, a temperature, and a flow rate.

B5. The system of paragraph B3, wherein the property includes at least one of a reservoir pressure within the subterranean formation, a bottom hole pressure within the stimulation well, a wellhead pressure of the production well, and a wellhead temperature of the production well.

C1. The use of any of the methods of any of paragraphs A1-A54 with any of the systems of any of paragraphs B1-B5.

C2. The use of any of the systems of any of paragraphs B1-B5 with any of the methods of any of paragraphs A1-A54.

C3. The use of any of the methods of any of paragraphs A1-A54 or any of the systems of any of paragraphs B1-B5 to produce a viscous hydrocarbon from a subterranean formation.

C4. The use of any of the methods of any of paragraphs A1-A54 or any of the systems of any of paragraphs B1-B5 to stimulate production of a viscous hydrocarbon from a subterranean formation.

C5. Viscous hydrocarbons produced using the method of any of paragraphs A1-A54 or the system of any of paragraphs B1-B5.

C6. The use of a pressure-cycling stimulation process in a stimulation well to increase production of a viscous hydrocarbon from a production well.

PCT1. A method of stimulating and producing viscous hydrocarbons from a subterranean formation that includes the viscous hydrocarbons, the method comprising:

increasing a pressure within a stimulation well that extends within the subterranean formation to increase a reservoir pressure to a pressure that is above an upper pressure threshold that is greater than a bubble point pressure of the viscous hydrocarbons;

decreasing the pressure within the stimulation well to decrease the reservoir pressure to a pressure that is below a lower pressure threshold that is less than the bubble point pressure of the viscous hydrocarbons;

repeating the increasing the pressure and the decreasing the pressure for a plurality of stimulation cycles; and

producing, as a reduced viscosity hydrocarbon stream, the viscous hydrocarbons from a production well that extends within the subterranean formation and is spaced apart from the stimulation well, wherein the producing includes producing during the increasing the pressure, the decreasing the pressure, and the repeating.

PCT2. The method of paragraph PCT1, wherein the increasing the pressure includes providing a stimulant fluid stream to the stimulation well.

PCT3. The method of paragraph PCT2, wherein the providing a stimulant fluid stream includes controlling a flow rate of the stimulant fluid stream to control a rate of the increasing by at least one of:

-   -   (i) increasing the flow rate of the stimulant fluid stream         responsive to the rate of the increasing being less than a         threshold lower increasing rate; and     -   (ii) decreasing the flow rate of the stimulant fluid stream         responsive to the rate of the increasing being greater than a         threshold upper increasing rate.

PCT4. The method of any of paragraphs PCT1-PCT3, wherein, subsequent to the increasing the pressure and prior to the decreasing the pressure, the method further includes maintaining the reservoir pressure above the upper pressure threshold for at least a threshold pressurized time.

PCT5. The method of paragraph PCT4, wherein the increasing includes providing a stimulant fluid stream to the stimulation well at a first flow rate, and further wherein the maintaining the reservoir pressure above the upper pressure threshold includes providing the stimulant fluid stream to the stimulation well at a second flow rate.

PCT6. The method of any of paragraphs PCT4-PCT5, wherein the threshold pressurized time is at least 1 day and less than 500 days.

PCT7. The method of any of paragraphs PCT4-PCT6, wherein the method further includes preserving a fluid temperature difference between a stimulant fluid stream and the reduced viscosity hydrocarbon stream below a threshold fluid temperature difference during the maintaining.

PCT8. The method of any of paragraphs PCT1-PCT7, wherein the decreasing the pressure includes at least one of ceasing providing a stimulant fluid stream to the stimulation well and decreasing a flow rate of the stimulant fluid stream to the stimulation well.

PCT9. The method of any of paragraphs PCT1-PCT8, wherein the decreasing the pressure includes liberating a solution gas from the viscous hydrocarbon while the viscous hydrocarbon is present within the subterranean formation.

PCT10. The method of any of paragraphs PCT1-PCT9, wherein, subsequent to the decreasing the pressure, the method further includes maintaining the reservoir pressure below the lower pressure threshold for at least a threshold depressurized time, wherein the threshold depressurized time is at least 1 day and less than 250 days.

PCT11. The method of any of paragraphs PCT1-PCT10, wherein the producing includes continuously producing the viscous hydrocarbons during at least 90% of a time period during which the increasing the pressure, the decreasing the pressure, and the repeating occurs.

PCT12. The method of any of paragraphs PCT1-PCT11, wherein the method further includes monitoring the reservoir pressure, wherein the decreasing the pressure includes decreasing the pressure based, at least in part, on determining that the reservoir pressure is greater than the upper pressure threshold, and further wherein the increasing the pressure includes increasing the pressure based, at least in part, on determining that the reservoir pressure is less than the lower pressure threshold.

PCT13. The method of any of paragraphs PCT1-PCT12, wherein the producing further includes producing the viscous hydrocarbons from the production well for a pre-production time prior to at least the decreasing the pressure and the repeating.

PCT14. The method of any of paragraphs PCT1-PCT13, wherein the method includes performing the method as part of at least one of a steam-assisted gravity drainage process, a solvent-assisted steam-assisted gravity drainage process, and a vapor extraction process.

PCT15. A system configured to produce viscous hydrocarbons from a subterranean formation, the system comprising:

a stimulation well that extends within the subterranean formation;

a stimulant fluid supply system that is configured to provide a stimulant fluid stream to the subterranean formation via the stimulation well;

a production well that extends within the subterranean formation and is configured to produce a reduced viscosity hydrocarbon stream from the subterranean formation; and

a controller that is programmed to control the operation of the system using the method of any of paragraphs PCT1-PCT14.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industry.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure. 

1. A method of stimulating and producing viscous hydrocarbons from a subterranean formation that includes the viscous hydrocarbons, the method comprising: increasing a pressure within a stimulation well that extends within the subterranean formation to increase a reservoir pressure to a pressure that is above an upper pressure threshold that is greater than a bubble point pressure of the viscous hydrocarbons; decreasing the pressure within the stimulation well to decrease the reservoir pressure to a pressure that is below a lower pressure threshold that is less than the bubble point pressure of the viscous hydrocarbons; repeating the increasing the pressure and the decreasing the pressure for a plurality of stimulation cycles; and producing, as a reduced viscosity hydrocarbon stream, the viscous hydrocarbons from a production well that extends within the subterranean formation and is spaced apart from the stimulation well, wherein the producing includes producing during the increasing the pressure, the decreasing the pressure, and the repeating, and wherein the production well is spaced-apart from the stimulation well.
 2. The method of claim 1, wherein the increasing the pressure includes providing a stimulant fluid stream to the stimulation well.
 3. The method of claim 2, wherein the providing a stimulant fluid stream includes controlling a flow rate of the stimulant fluid stream to control a rate of the increasing by at least one of: (i) increasing the flow rate of the stimulant fluid stream responsive to the rate of the increasing being less than a threshold lower increasing rate; and (ii) decreasing the flow rate of the stimulant fluid stream responsive to the rate of the increasing being greater than a threshold upper increasing rate.
 4. The method of claim 1, wherein, subsequent to the increasing the pressure and prior to the decreasing the pressure, the method further comprises maintaining the reservoir pressure above the upper pressure threshold for at least a threshold pressurized time.
 5. The method of claim 4, wherein the increasing includes providing a stimulant fluid stream to the stimulation well at a first flow rate, and wherein the maintaining the reservoir pressure above the upper pressure threshold includes providing the stimulant fluid stream to the stimulation well at a second flow rate.
 6. The method of claim 4, wherein the maintaining includes controlling a flow rate of a stimulant fluid stream to maintain the reservoir pressure above the upper pressure threshold.
 7. The method of claim 4, wherein the threshold pressurized time is at least 1 day and less than 500 days.
 8. The method of claim 4, further comprising preserving a fluid temperature difference between a stimulant fluid stream and the reduced viscosity hydrocarbon stream below a threshold fluid temperature difference during the maintaining.
 9. The method of claim 1, wherein the decreasing the pressure includes at least one of ceasing providing a stimulant fluid stream to the stimulation well and decreasing a flow rate of the stimulant fluid stream to the stimulation well.
 10. The method of claim 1, wherein the decreasing the pressure includes liberating a solution gas from the viscous hydrocarbon while the viscous hydrocarbon is present within the subterranean formation.
 11. The method of claim 1, wherein, subsequent to the decreasing the pressure, the method further comprises maintaining the reservoir pressure below the lower pressure threshold for at least a threshold depressurized time, wherein the threshold depressurized time is at least 1 day and less than 250 days.
 12. The method of claim 1, wherein the repeating includes repeating the increasing and the decreasing for at least 10 stimulation cycles.
 13. The method of claim 1, wherein the repeating includes performing the increasing the pressure and subsequently performing the decreasing the pressure in each stimulation cycle of the plurality of stimulation cycles.
 14. The method of claim 1, wherein the producing includes continuously producing the viscous hydrocarbons during at least 90% of a time period during which the increasing the pressure, the decreasing the pressure, and the repeating occurs.
 15. The method of claim 1, further comprising monitoring the reservoir pressure.
 16. The method of claim 15, wherein the decreasing the pressure includes decreasing the pressure based, at least in part, on determining that the reservoir pressure is greater than the upper pressure threshold.
 17. The method of claim 15, wherein the increasing the pressure includes increasing the pressure based, at least in part, on determining that the reservoir pressure is less than the lower pressure threshold.
 18. The method of claim 15, wherein the monitoring the reservoir pressure includes calculating the reservoir pressure.
 19. The method of claim 1, wherein the producing further comprises producing the viscous hydrocarbons from the production well for a pre-production time prior to at least the decreasing the pressure and the repeating.
 20. The method of claim 1, further comprising performing the method as part of at least one of a steam-assisted gravity drainage process, a solvent-assisted steam-assisted gravity drainage process, and a vapor extraction process.
 21. A system configured to produce viscous hydrocarbons from a subterranean formation, the system comprising: a stimulation well that extends within the subterranean formation; a stimulant fluid supply system that is configured to provide a stimulant fluid stream to the subterranean formation via the stimulation well; a production well that is spaced-apart from the stimulation well, extends within the subterranean formation, and is configured to produce a reduced viscosity hydrocarbon stream from the subterranean formation; and a controller that is programmed to control the operation of the system using the method of claim
 1. 